In various well related operations, the density of the rock matrix and the fluid are needed for proper interpretation of the log measurements and other decisions. The matrix density of a formation can be determined from core analysis or spectroscopy logging. However, these techniques do not enable estimation of the apparent fluid density. In many applications, near-wellbore fluids composition and distribution can be very complex. For example, wells drilled with oil-based mud can create near-wellbore fluid compositions with a variety of fluids in complex distributions. Currently, density/total porosity is computed by using an ad hoc constant fluid density. However, the fluid density often is complex rather than constant and thus use of constant fluid density can lead to erroneous estimations of porosity.
Studies have been conducted regarding near-wellbore fluids to investigate near-wellbore fluid mixtures at a single depth of investigation. For example, three dimensional nuclear magnetic resonance (T1, T2, D) maps have been created regarding fluid measurements at the single depth of investigation. In some environments, very complex fluid mixtures can include a variety of fluids, including water, oil, oil-base mud, and condensate/gas. However, fluid maps acquired at a single depth of investigation cannot be relied on as representative of the fluids mixture measured by the density logging tool.